The state will soon have special rate structures for homes
and businesses that want to invest in battery-backed solar or EVs—but the
details are subject to debate.
California is already breaking ground in attempting to
properly value the distributed technologies hitting the grid. So far, that’s
been done through large-scale capacity contracts, demand response auction
mechanisms, and utility pilots. Now the state is opening another front in
distributed energy integration: tariffs.
These rates would change from hour to hour, but with drastic
price differentials between on-peak and off-peak times than the mass-market
time-of-use (TOU) rates being rolled out across the state over the next four
years. Such extreme price differentials could punish customers who can’t shift
energy use.
But they could also provide the financial incentives to
cover the costs of adding a battery to a new or existing solar PV installation,
to charge up when prices are low and discharge when they’re high. And unlike
mass-market TOU rates, they could include different measures of real-time value
-- price changes based on wholesale grid power costs, for example, or demand
charges or distribution grid values aimed at getting customers to change
energy-use patterns to mitigate local grid congestion needs.
All of these options are now on the table in the general
rate cases being put forward by Pacific Gas & Electric, Southern California
Edison and San Diego Gas & Electric. PG&E’s rate case is coming first
-- and we’ve already seen new tariff proposals come out from the utility and
from the Solar Energy Industries Association (SEIA), two parties that have
clashed before over solar-friendly rate design.
Two different approaches to solar-storage tariff
design
This week, SEIA filed testimony with the California Public Utilities Commission asking
the regulator to reject PG&E’s proposed solar-storage rate schedules for
residential and small commercial customers, and to go instead with an
SEIA-designed set of rates. The solar group has also proposed a new “Option S”
rate for large commercial and industrial customers to encourage solar-storage
systems, something that PG&E hasn’t yet considered in its rate cases.
SEIA lays out two main reasons why it doesn’t like
PG&E’s rate schedules for residential and small commercial customers,
called E-DMD and A1-DMD, respectively, and why it wants to replace them with
its own E-STORE and A1-STORE rates instead.
PG&E’s rates would include a “significant non-coincident
demand charge based on the customer’s maximum 15-minute demand each month,
whenever it occurs.” And as we’ve seen from debates
around the country, while some utilities have supported adding demand
charges to solar net metering customers, solar industry groups have universally
opposed them.
“We’re categorically opposed to residential demand charges,”
SEIA’s Brandon Smithwood said in a Wednesday interview, making PG&E’s idea
of adding demand charges to its residential rate a non-starter.
And while SEIA isn’t opposed to demand charges for small
commercial customers, it would like to implement them in a different way.
Instead of basing them on any single 15-minute spike over the course of a
month, it’s proposing “daily demand charges,” imposed on customers only during
the day’s peak demand hours.
The difference, Smithwood explained, is that “with a monthly
demand charge, it’s just that one 15-minute interval.” If a customer fails to
prevent it, they've “blown [their] savings for the month.” With a daily demand
charge, by contrast, “We could shape that demand charge so that it really sends
a better price signal. We would be moving demand charges toward something that
actually works better for customers, and makes more sense for a public policy
standpoint.”
California hasn’t used daily demand charges before, making
SEIA’s proposal a novelty in the state's utility policy. Here’s how it
describes the concept in its testimony: “The daily demand charge of $0.6390 per
kW/day applies each and every day to the highest 60-minute demand during the 3
p.m. to 8 p.m. peak period. This rate element provides the storage user with a
strong incentive to use storage both to reduce and to flatten their delivered
load from the utility during the peak period, and to discharge storage when the
stored power provides the greatest system benefits.”
The second big problem SEIA has with PG&E’s proposal is
that it doesn’t believe the differences between on-peak and off-peak prices are
significant enough. “It just won’t pencil out,” he said. “Even if you could
manage your non-coincident residential demand charges, there’s not enough
differential there.”
SEIA’s rate differentials, by contrast, are quite high -- as
much as 40 cents between the 52 cents per kilowatt-hour on-peak price and the
12 cents per kilowatt-hour off-peak price for residential customers under its
E-STORE rate.
But this is the kind of “spicy” differential needed to cover
the extra costs of adding batteries to solar, which SEIA has estimated at 33
cents per kilowatt-hour. “You need the big -- 'spicy' is the word commission
staff like to use -- more ambitious, more technology-focused, time-of-use
rates, with that big differential between on-peak and off-peak,” Smithwood
said.
SEIA’s testimony backs this up with its own analysis of how
a 10-kilowatt-hour battery, cycling daily between the off-peak and peak
periods, would fare over a year's time under both proposed rates. Under the
E-STORE rate, that system would realize $1,062 per year in benefits -- “economic
if such storage units have reliable lives of 10 years and costs below $10,000.
Such units appear to be commercially available soon, for example, the Tesla
Powerwall 2.”
In contrast, “We estimate that [PG&E’s] E-DMD rate will
provide annual benefits of just $509, assuming optimistically that the storage
can reduce the customer’s non-coincident demand charge by 50 percent of the
unit’s output capacity.”
At present, PG&E hasn’t provided an alternative analysis
of its own rates. The utility recently testified to the CPUC that it “did not
perform any analysis to determine the point at which the solar plus on-site
battery storage would become economic under the proposed E-DMD and A1-DMD
residential and small commercial rates.”
The intricacies of creating, and comparing,
never-before-seen DER tariffs
These are only two sets of multiple DER tariffs being
proposed in California, and it can be hard to parse out the complex differences
between all of them. At GTM's California’s Distributed Energy Future 2017 conference
held last week in San Francisco, we heard a
debate between SEIA’s Sean Gallagher and Environmental Defense Fund
senior economist James Fine over another proposal coming from SDG&E,
specifically for EV charging.
EDF’s Fine pointed out that SDG&E’s experimental tariff
for its Vehicle-to-Grid Integration pilot would be based on day-ahead forecasts
of hour-by-hour prices the next day, with some adjustment for day-of changes.
That will give EV drivers -- or the EVs themselves -- the data required to
avoid high-price hours and take advantage of low-price hours.
EDF is also asking PG&E and Southern California Edison
to consider what it calls a “smart home rate,” which would expand the scope of
customers beyond single-technology categories like solar-storage or EVs, to
include demand response via smart thermostats, grid-responsive loads and other
behind-the-meter controls.
The basic concept includes some sort of monthly service fee
(albeit one that's as low as possible); a grid charge that allows customers to
benefit by managing their load profile; and day-ahead hourly price signals that
accurately reflect a broad range of costs and values.
Gallagher previewed SEIA’s E-STORE proposal in his CDEF
talk, but also provided a critique of what SDG&E and EDF have proposed. In
his view, hour-by-hour prices that change daily might push too much risk onto
the customers and provide “too much certainty for the utility,” he said.
Fine agreed that “the concern is that this is maybe too
risky for many customers.” On the other hand, he acknowledged that “there’s
also an attractive, profitable opportunity for customers who want to take on
that risk” -- or perhaps are willing to hire a DER provider or aggregator to do
it for them.
Given all the uncertainty over how these kinds of rates will
work in the real world, both Gallagher and Fine agreed that it’s important to
have a number of options available to customers.
Both also promoted tariffs that don’t just compel people to
reduce energy at moments of high costs and high demand, but that also offer
incentives to actually increase energy use during negative pricing events when
demand is low and renewable energy supply is high -- such as during the midday belly
in California’s "duck curve."
SEIA’s concept for this is called “discount days,” which
would work along the lines of the critical peak pricing days widely used
by California utilities (only in reverse), while EDF’s concept would embed
these discounts in day-ahead pricing.
The debate over DER-based tariffs is just beginning, but
this will be the year that helps set the terms for rollouts across the state.
PG&E’s general rate case will likely take until the end of 2017 to
complete, SDG&E’s is set to close it in the third quarter, and Southern
California Edison’s will conclude in 2018.
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